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Directive 046

Directive 046: Production Audit Handbook January 2003 Effective June 17, 2013, the Energy Resources Conservation Board (ERCB) has been succeeded by the Alberta Energy Regulator (AER). As part of this succession, the title pages of all existing ERCB directives now carry the new AER logo. However, no other changes have been made to the directives, and they continue to have references to the ERCB. As new editions of the directives are issued, these references will be changed. Some phone numbers in the directives may no longer be valid. Contact AER Inquiries at 1-855-297-8311 or [email protected].

Directive 046

Production Audit Handbook January 2003 (with updates June 2011)

June 2011 This directive has been updated to reflect changes that have been made in Directive 017 (April 2011 edition). Sections no longer required have been grayed out. This directive has also been updated to reflect the name change of EUB to ERCB and renaming guides to directives.

Energy Resources Conservation Board Directive 046: Production Audit Handbook 2nd edition, January 2003 Published by Energy Resources Conservation Board Suite 1000, 250 5 Street SW Calgary, Alberta T2P 0R4 Telephone: (403) 297-8311 Toll free 1-855-297-8311 Web site:

Contents 1 Overview ................................................................................................................................... 1 1.1 Whats New in This Edition ............................................................................................ 1 1.2 Production Audits ............................................................................................................ 2 1.3 What This Guide Contains .............................................................................................. 3 2 Selecting a Facility for Audit .................................................................................................... 3 3 Preinspection Procedures .......................................................................................................... 4 3.1 Facility/Corporate Familiarization................................................................................... 4 3.2 Notifications .................................................................................................................... 5 3.3 Preparations ..................................................................................................................... 5 4 The Facility Inspection.............................................................................................................. 6 4.1 Oil Batteries Equipment Inspection................................................................................. 6 4.2 Oil Batteries Operational Procedures .............................................................................. 7 4.2.1 Tank Gauging ........................................................................................................ 7 4.2.2 Gas Charts.............................................................................................................. 7 4.2.3 Proration Testing Procedure .................................................................................. 7 4.2.4 Header Switching................................................................................................... 8 4.2.5 Basic Sediment and Water (BS&W) or Water-Cut Procedure for Test Production ................................................................................................ 8 4.2.6 Trucked Fluid Receipts and Deliveries.................................................................. 9 4.3 Other Oil Battery Information ......................................................................................... 9 4.4 Gas Batteries Equipment Inspection.............................................................................. 10 4.5 Gas Batteries Operational Procedures ........................................................................... 11 4.5.1 Tank Gauging ...................................................................................................... 11 4.5.2 Gas Charts............................................................................................................ 11 4.5.3 Truck Fluids Receipts and Deliveries .................................................................. 11 4.5.4 Test and Sampling Procedures............................................................................. 11 4.6 Other Gas Battery Information ...................................................................................... 11 5 Records Review....................................................................................................................... 12 5.1 Oil Batteries................................................................................................................... 13 5.1.1 Oil Battery Production Reports............................................................................ 13 5.1.2 Oil Battery Equipment ......................................................................................... 13 5.1.3 Oil Battery Procedures and Records .................................................................... 16 5.1.4 Oil Battery Accounting........................................................................................ 18 5.2 Gas Batteries.................................................................................................................. 22 5.2.1 Gas Battery Production Reports .......................................................................... 22 5.2.2 Gas Battery Equipment ........................................................................................ 22 5.2.3 Gas Battery Procedures and Records................................................................... 23 5.2.4 Gas Battery Accounting....................................................................................... 24 5.3 Audit Results ................................................................................................................. 27 Appendix A Liquid Measurement ............................................................................................... 29 A-1 Recommended Rates and Pressure Drops for Liquid Meters ........................................ 29 A-2 Tank Gauging Procedure ............................................................................................... 33 (continued)

ERCB Guide 46: Production Audit Handbook (January 2003) i

ii ERCB Guide 46: Production Audit Handbook (January 2003)

A-3 Well Test Tank Diameter Sizing Guidelines ................................................................. 34 A-4 Split Loads Guideline .................................................................................................... 35 A-5 Cascade Testing............................................................................................................. 36 Appendix B Gas Measurement.................................................................................................... 37 B-1 Gas Volume Calculation................................................................................................ 37 B-2 Acid Gas Measurement.................................................................................................. 39 Appendix C Fluid Sampling and BS&W .................................................................................... 42 C-1 Fluid Samplers............................................................................................................... 42 C-2 Water-Cut Analyzers ..................................................................................................... 43 C-3 Water-Cut (BS&W) Procedure...................................................................................... 49 Appendix D Inspection Guidelines.............................................................................................. 55 D-1 Orifice Meter Inspection Guidelines ............................................................................. 55 D-2 Orifice Meter Measurement Error Percentage............................................................... 59 D-3 Common Errors in Orifice Meter Chart Interpretation .................................................. 61 D-4 Guide to Good Gas Charts and Gas Chart Reading....................................................... 62 D-5 Guidelines for Inspecting Automated Measurement Systems ....................................... 63 1 General Inspection Guidelines ................................................................................ 63 2 Automated Measurement Systems: General Description and Requirements.......... 66 2.1 SCADA Systems .............................................................................................. 67 2.2 Flow Computers ............................................................................................... 71 2.3 Gas Measurement ............................................................................................. 71 2.4 Liquid Measurement Systems .......................................................................... 72 2.5 End Device Calibrations................................................................................... 72 3 Review and Evaluation ........................................................................................... 73 3.1 Database Review .............................................................................................. 73 3.1.1 Database Changes ................................................................................... 73 3.1.2 Handling Reports .................................................................................... 73 3.1.3 Printed Reports ....................................................................................... 73 3.1.4 System Reliability................................................................................... 74 3.2 Performance Evaluation ................................................................................... 74

3.2.1 Test Cases for Verification for Orifice Meter Gas Flow Calculation Programs ................................................................................................. 74

Appendix E Determining Gas Estimates..................................................................................... 82 E-1 Method to Estimate Fuel Gas ........................................................................................ 82 E-2 Gas-in-Solution.............................................................................................................. 84 E-3 Gas Equivalent Factor Determination ........................................................................... 89 Appendix F EUB Forms and Diagrams ...................................................................................... 97 F-1 Production Data Sheet ................................................................................................... 97 F-2 Data Request Letter and Sheet....................................................................................... 99 F-3 Facility Check Sheet.................................................................................................... 103 F-4 Production Audit Enforcement Ladder Definitions..................................................... 107 Appendix G Metric Conversions and API and AGA Standards................................................ 108 G-1 Metric Conversions...................................................................................................... 108 G-2 API and AGA Standards for References ..................................................................... 112 Appendix H Applicable EUB Documents ................................................................................. 114

1 Overview This Production Audit Handbook, Directive 46, defines the production audit protocols for the Energy Resources Conservation Board (ERCB) and is designed to ensure that ERCB auditors conduct production audits of oil and gas production facilities, gas plants, and injection systems in a consistent manner throughout Alberta. The Directive is available to industry to enhance understanding and communication between production accounting and operating personnel in industry and ERCB staff.

1.1 Whats New in This Edition This revised edition of Directive 46 includes an overall enhancement of selection criteria, audit procedures, and protocols. In addition, the former appendices have been updated, as follows: Appendix A-2 Revised Tank Gauging Procedure Appendix A-3 Changed tank sizing coefficient from 0.69 to 0.39 Appendix A-4 Added New Split Loads Policy Appendix A-5 Added Cascade Testing Appendix B-1 Removed appendix on Confirming Integrator Values and renamed

former Appendix B-2: Gas Volume Calculations as B-1; added AGA3 (1990) calculation formula

Appendix B-3 Removed this appendix on Determination of Supercompressibility

(hand calculations) Appendix B-4 Renumbered Acid Gas Measurement as Appendix B-2 Appendix B-5 Combined with Gas Volume Calculation in Appendix B-1 Appendix C-3 Recommended water-cut procedure has been modified to include

various BS&W ranges Appendix D-1 Added that new sales/gas delivery point orifice meters must conform

to the latest AGA3 specifications Appendix D-4 Removed Conversion of Planimeter Readings to Values of hw and

Pf (hand calculation); added new integration technology submission rule for audits Appendix D-5 Transferred Guidelines for Inspecting Automated Measurement

Systems from Directive 64, Appendix 5, with modification to accuracy, calibration, audit submission, and reporting requirements; added upstream pressure tap factors and parameters to test cases

Appendix D-6 Removed LPG Storage Vessel Code (transferred to Directive 64) Appendix E-2 Added Gas-in-Solution determination requirements Appendix E-3 Modified Gas Equivalent Factor formulas and liquid to gas

conversion according to 2003 Gas Processors Association (GPA) factors

ERCB Directive 46: Production Audit Handbook (January 2003) 1

Appendix F-2 Updated Data Request Letter and Sheet

Appendix F-3 Added the updated Facility Check sheet (combined previous Appendices F-5 and F-6)

Appendix F-4 Added Production Audit Enforcement Ladder Definitions Removed previous Appendices F-3, F-4, and F-7 Appendices G and HUpdated list of API and AGA standards and ERCB

Directives, interim directives (IDs), and informational letters (ILs)

1.2 Production Audits The ERCB conducts detailed production audits of oil and gas facilities in Alberta to ensure that facilities are constructed and operated in accordance with the Oil and Gas

Conservation Act and Regulations, Oil Sands Conservation Act and Regulations, other ERCB requirements, and the facility licence or approval;

ERCB standards for measurement accuracy are being met; monthly production reports are completed in a satisfactory manner; environmental concerns are dealt with; and companies are aware of the ERCB enforcement ladder of escalating consequences for

noncompliance. A production audit selectively monitors production operations licensed by the ERCB, with an emphasis on production measurement and reporting. It involves evaluations of process equipment, measurement, and SCADA devices, operation and measurement procedures, accuracy and completeness of recorded data, accounting procedures, data processing (production accounting programs), and completion of production reports. In the course of completing an audit, the ERCB auditor applies the requirements outlined in this Directive, as well as those in Oil and Gas Conservation Act and Regulations (OGCA and OGCR) Oil Sands Conservation Act and Regulations (OSCA and OSCR) Directive 7: Production Accounting Handbook Directive 55: Storage Requirements for the Upstream Petroleum Industry Directive 56: Energy Development Application

2 ERCB Directive 46: Production Audit Handbook (January 2003)

Directive 60: Upstream Petroleum Industry Flaring Directive 64: Facility Inspection Manual Internal Guide 8: Safety Manual industry standards (see Appendices G-2 and H)

1.3 What This Directive Contains This Directive provides instructions on how auditors should conduct production audits and includes Selecting a Facility for Audit Preinspection Procedures Facility Inspection Procedures Records Review Procedures Appendices with detailed procedures and guidelines, calculations, forms, and

conversion factors. Appendices G and H list all API and AGA standards and ERCB documents (Directives, IDs, and ILs) cited in this Directive.

2 Selecting a Facility for Audit Any upstream facility is subject to audit at any time. However, most audit candidates are selected by the Production Audit section based on one or more of the following criteria: previous unsatisfactory audits or inspections of any of the licensees facilities significant trucked-in production, by volume or percentage of total facility

throughput questionable custody transfer measurement facilities with mixed measurement and/or well types consistently poor proration factors or high metering differences facilities with excessive flaring and venting facilities subject to allowables or GOR penalties external and internal requests unapproved facilities random selection other criteria that may arise


3 Preinspection Procedures The ERCB auditor must notify the appropriate Field Centre that an audit is to be conducted in the coming months. The Field Centre may elect to conduct a joint audit. The auditor must then review documentation on the facility and notify the licensee of the upcoming audit.

3.1 Facility/Corporate Familiarization

Check the corporate information on the computer system to determine licensee status. Review all available internal files regarding the facility and the licensee history. Note that beginning with the October 2002 reporting month and the implementation of the Petroleum Registry, the previous S statements are now called monthly volumetric submissions. Gather information on previous audits, field inspections, special approvals, and requirements. This may be obtained from the battery or plant file available from the Microfilm Section in Calgary. Obtain a copy of a recent schematic from the licensees operation contact to take to the facility. Obtain a copy of the well listing for the facility. Note the status of each well. Review the facility approval licence and schematics. Become familiar with the facility design, equipment, metering points, sample points, header system, injection system, satellites, and fluid disposition. Identify meter bypass routes, unmetered fluid streams, transfer points, common flow lines, and field headers. Review several months of production reports. Note potential problem areas, such as proration test frequency required based on oil production volume of each oil well gas well tied into oil batteries and vice versa poor proration factors excessive metering differences or none reported where expected excessive flaring no flared, vented, or fuel gas reported reporting measured production at flow-lined wells well status incorrect large receipt volumes of trucked-in oil Review other approvals for terms and conditions that may affect measurement and operations, such as allowables disposal, pressure maintenance, enhanced oil recovery (EOR) approvals injection wells maximum rates and pressures source and measurement of injection fluids approvals for charts greater than 8-day cycle miscellaneous orders and approvals gas measurement exemptions microfilm records production surveillance history


Prepare a tentative inspection procedure to ensure that all items of interest are checked (see Appendices F-1 and F-3).

3.2 Notifications Notify the appropriate ERCB Field Centre at least one week prior to the site inspection. In the case of First Nations sites, notify Indian Oil and Gas Canada (IOGC) and the Band office, and for Metis settlements, notify Metis Counselor and Settlement offices. Notify the licensee of your intention to audit the facility. Explain the purpose of the audit and how it will be conducted, including setting a time and place to meet, putting a well on test for proration batteries, and demonstrating sampling and basic sediment and water (BS&W) procedures on site. Do not arrive at the facility unannounced. Contact someone at the facility at the production superintendent/production operations manager level to advise of the impending audit. This person or a delegate will be responsible for procuring the requested information (e.g., site schematic drawings, production records), ensuring that remedial measures are completed, and meeting with you at the completion of the audit (records review).

3.3 Preparations Contact the field foreman and/or battery operation personnel to arrange the field inspection and advise that it will take at least one day to inspect a gas battery and usually two days for oil batteries. Ensure that the facility will be operating normally. Attempt to schedule your inspection to conform to the normal schedule of the operation personnel. Try to evaluate the operating procedure under normal, routine conditions. Ensure that the operation personnel and field foreman understand their role in the audit process. They are to show the auditor the requested facilities, put wells on test if applicable, perform their normal duties, and answer any questions regarding field operational issues. (Ask them to wait until you arrive before proceeding with the testing.) Request that any stabilization or purge procedure be completed prior to your arrival so that the well is ready to go on test. If you wish to witness the testing of specific wells because of allowables, royalty relief, common flow lines, etc., advise the operation personnel in advance. Find out if you require special safety equipment or a work permit to enter the lease. Conform to the requirement. Find out if the facility is locked when unattended; if so, arrange access. If wells at the battery qualify for gas measurement exemption, try to schedule the inspection during the annual retest or request a gas test if possible.


4 The Facility Inspection Carry out the facility inspection in accordance with Directive 64. The major portion of the inspection involves evaluation of the battery equipment and ERCB accounting meters, observation of the measurement procedures, and gathering information on production characteristics of the well(s), the operating

procedures, field records, and production data capture. Careful and detailed documentation of the field inspection data is very important. You may summarize the data gathered on the Production Data Sheet for oil batteries as shown in Appendix F-1. Note that new technology and methodology used in measurement are allowed, provided that the licensee can demonstrate that it can operate within the uncertainty guidelines in the OGCR Schedule 9.

4.1 Oil Batteries Equipment Inspection Confirm the accuracy of the flow diagram on file and note any changes. Sketch your own flow diagram if necessary. Conduct a battery inspection as outlined in Directive 64. Pay particular attention to its Appendix 1, Sections 1 to 4, on measurement. Record the following accounting meter data: Liquid meters manufacturer, serial and model number, calibration date, meter

factor, and method of temperature compensation. Does the metering conform to OGCR, Section 14.180? If not, is there a special reason? See Appendix A-1 for recommended flow rates.

Water meters must comply with OGCR, Sections 14.140, 14.160, 14.170, and

14.180. Orifice meters static, differential and temperature ranges, chart drive speed,

upstream run size, manufacturer, serial and model number, manufacture and calibration dates; have the operation personnel pull plate in meter if possible; check spare plates for damage and proper storage. Orifice meters must comply with OGCR, Section 14.070, which requires compliance with the latest American Gas Association Report No. 3 (AGA3) for orifice meter installation requirements, including minimum upstream and downstream pipe lengths. (See Meter run inspection in Appendix D-1.)

Other meters meter factors, manufacture and calibration dates, manufacturer, serial

and model number, flow rate through meter. Are the meters temperature or pressure compensated?

Automated measurement systems any measurement performed using electronic or

SCADA equipment must conform to the requirements of Appendix D-5. Check to ensure that the meter bypass is closed for all accounting meters. If it is not,

ask why.


Record the capacity and dimensions of each storage tank. Are tanks on automatic level control? At what levels do the control switches engage? Do gauge boards have the proper increments (see Appendix A-2)? Record daily gauges and time of gauge. Is secondary containment in place (see Directive 55)? Record approximate density of oil in tanks from past records. Are tanks equalized? Record the pressure and temperature of each process vessel. Record header pressures (test and group lines). Initial each chart for verification during records review. Are any wells using casing head gas for fuel? Is it measured? Estimated?

4.2 Oil Batteries Operational Procedures Operation personnel are a valuable source of information. Ask questions, observe, and listen carefully. Accompany the operation personnel on his rounds to satellites and well sites. You should check as many wells as possible within the time frame of the inspection. Discretion is required as to what type and which well(s) you should choose to go to. The well(s) on test should be inspected. Inspect equipment and observe procedures at each installation. Note any adjustments made to wellhead or process equipment. 4.2.1 Tank Gauging (see Appendix A-2 for tank gauging procedure) Check the tank gauging method for accuracy, and record the gauge readings taken by the operation personnel. Observe how the operation personnel gauges each tank, including equalized tanks. If tank gauging is not performed, ask the operation personnel to do so on site. This is only considered a deficiency if it is not done under one of these conditions: 1) at month end 2) as the only means of trucked-in measurement 3) tank used as a test tank Verify frequency of gauging. See Appendix A-3 for test tank sizing. 4.2.2 Gas Charts See Appendix D for recommended gas chart operating procedures, integration standards, documentation, etc. 4.2.3 Proration Testing Procedure The testing of conventional oil wells is to be done in accordance with the criteria set in ID 94-1 and Schedule 16 of OGCR, as well as ID 91-3 for heavy oil. The following


information, to be obtained from the operation personnel, will help you to assess the integrity of the testing operation: criteria for accepting or rejecting well tests well purging and/or stabilization procedure testing procedure following shut-in periods or when production conditions have

changed general production characteristics of the wells fluid rates, water-cut ranges,

production stability, and problem wells procedure, equipment, and frequency for GOR testing of gas measurement exempt

wells In addition, the following questions must be answered: Are wells on timers? Do wells flow when not pumping? Does production time include the nonpumping hours? Are there any common flow lines in the system? How often are flow lines pigged, and does this affect flow rates? Do they retest after

pigging? In your inspection field notes, record the test liquid readings (meter or tank) to two (2) decimal places for the well test being witnessed. Record the time the test went on. Take note if the operation personnel resets the meter before every test (if applicable), and record the readings to two decimal places. Determine how and when the meter correction factor is applied, if applicable. 4.2.4 Header Switching Confirm that the well put on the test is the same as indicated on the test chart from header or field valving. Also check if the well is on stream by checking valve positions on the wellhead. Are the wells adequately identified at the header? Do wells have adequate time to stabilize at test conditions prior to testing? 4.2.5 Basic Sediment and Water (BS&W) or Water-Cut Procedure for Test Production Review of the BS&W procedure is normally done on the second day of the field audit, when the proration test is completed and the sample collected. A wellhead sample is not recommended for conventional oil but is allowed below 10 per cent BS&W; however, it is acceptable for heavy oil (>920 kg/m3). Observe the operation personnels normal water-cut procedure. Document the procedure and results. Ensure that the operation personnel collects a large enough sample, according to Appendix C-3. Allow the operation personnel to complete the procedure before commenting on the accuracy of the methods used. See Appendix C-3 for recommended water-cut procedure.


4.2.6 Trucked Fluid Receipts and Deliveries Try to witness truck loading or off-loading to observe the procedure for measurement, sampling, and water-cut. See IL 90-6 and IL 92-8 for guidelines and Appendix C-3 for recommended water-cut procedure.

4.3 Other Oil Battery Information Day One of Inspection Through your observations or by questioning the operation personnel, gather the following information: Record any other meter readings, such as fuel gas, flare, condensate or LPG, group

oil or water, water injection or disposalanything that affects the accounting at the battery.

Determine how products are transported or sold from the battery (through pipeline,

truck, etc.). Determine the type of field data capture system used, such as the accounting

procedure or software used to calculate the volumes. Record the type of measurement used to determine the sales volume (LACT, tank

gauging, etc.). Record the meter reading or gauge reading taken by the operation personnel.

Fill out Facility Check Sheet (Appendix F-3) and send to the appropriate Field

Centre. Check what data are recorded and where they are recorded. Review all log(s), load

oil injection/recovery records, gauge sheets, test records, trucking records, water injection records, etc., and have the operation personnel explain each entry and calculation. Determine what records are sent to the operating companys head office.

Record the method of measurement or estimate of blowdown gas and the blowdown

frequency. It is important to take detailed notes before you leave the lease, when your observations are fresh in your mind. Go over your notes and elaborate if necessary. Write down any points you may have missed or points requiring further clarification. Day Two of Inspection On the second day of your inspection, confirm all procedures and operating conditions, note any changes, and gather any information you missed the previous day. Record all meter readings taken by the operation personnel, as done on the previous day. Record the time off for the well test(s) witnessed.


4.4 Gas Batteries Equipment Inspection Confirm the accuracy of the flow diagram on file. Note any changes or additions. Sketch your own flow diagram if necessary, noting all measurement points. Record the following meter data: Liquid meters manufacturer, serial and model number, calibration date, meter

factor, flow rate through meter. Does the metering conform to OGCR, Section 14.180? If not, is there a special reason? See Appendix A-1 for recommended flow rates.

Condensate meters must comply with OGCR, Sections 14.090 and 14.180, and water

meters must comply with OGCR, Sections 14.140 and 14.160 to 14.180. Orifice meters static, differential and temperature ranges, chart drive speed,

upstream run size, manufacturer, serial and model number, manufacture and calibration dates; have operation personnel pull the plate in use, if possible, and check spare plates for damage and proper storage. Orifice meters must comply with OGCR, Section 14.070, and conform with AGA3 for orifice meter installation requirements, including minimum upstream and downstream pipe lengths. (See Meter run inspection in Appendix D-1.)

Other gas meters calibration date, manufacturer, serial and model number, flow rate

through meter. Are these meters temperature or pressure compensated? (See Appendix B-1 for calculations.)

Automated measurement systems any measurement performed using electronic or

SCADA equipment must conform to the requirements of Appendix D-5. Check to ensure that the meter bypass is closed for all accounting meters. Try to witness the meter calibration procedure if possible. Note any unmetered gas, condensate, LPG, or water streams (fuel, recycle, etc.). Record the capacity and dimensions of each storage tank, including LPG bullets. Record the pressure and temperature of each process vessel and liquid sampling point. Initial each chart for verification during records review. Check approval for any chart greater than 8 days. Complete a Facility Check Sheet (Appendix F-3). Vessel drain line must be directed to a suitable container or bull plugged and not directed to a pit. Check if condensate tank vapours are vented, gathered, or flared. Record the volume of vented gas measured or estimated. Check the location of test taps for effluent measurement wells or for southeast Alberta proration wells. (See Section 4.5.4: Test and Sampling Procedures, below.)


4.5 Gas Batteries Operational Procedures Operation personnel are a valuable source of information. Ask questions, observe, and listen carefully. Accompany the operation personnel on rounds to the well sites. Check as many wells as possible within the time frame of the inspection. Discretion is required as to what type and which well(s) you should choose to go to and if you should visit all well(s) on test (proration or effluent measurement systems). Inspect and observe procedures at each installation. Note any adjustments made to wellhead or process equipment. 4.5.1 Tank Gauging (see Appendix A-2 for operating procedures) 4.5.2 Gas Charts (see Appendix D-1 for operating procedures) 4.5.3 Trucked Fluid Receipts and Deliveries (see IL 90-6 and IL 92-8 for operating

procedures) 4.5.4 Test and Sampling Procedures For gas wells in southeast Alberta proration systems and any other systems approved for proration, ensure that well tests are conducted and volumes determined in accordance with IL 93-10 and Directive 7, Appendices 10 and 11. For gas wells that require semi-annual water rate testing, ensure that procedures outlined in Directive 4 for determining water production are followed. Ensure that water/gas ratios (WGR) records are updated and reported accordingly. For effluent wellhead measurement, ensure that the test taps are located downstream of the effluent meter and the effluent correction factors (ECF) are updated accordingly. Record the operating temperature and pressure at the gas meter run or at the effluent meter run. Check for up-to-date meter calibrations (see ID 90-2). This is to be done once every 12 months for gas meters and once every 6 months for condensate meters. Shop calibration of condensate meters is permissible when the condensate rate is less than 2 cubic metres per day (m3/d) or less than 3 m3/d and the gas equivalent volume of the condensate is less than 3% of the measured gas volume. (Also see Directive 64, Section 2.1(d).) Check flow rate through liquid meter (see Appendix A-1). Check BS&W determination procedures (see Appendix C-3). Record any other meter readings or tank gauges, such as fuel, flare, condensate, water disposal, blowdown, and anything that affects the accounting at the battery.

4.6 Other Gas Battery Information Through your observations or by questioning the operation personnel, gather the following information: Field records What data are recorded and where are they recorded? Review all log

books, gauge sheets, test records, trucking records, water injection records, etc., and


have operation personnel explain each entry and calculation. Determine what records are sent to head office.

Measurement or estimate of blowdown gas; blowdown frequency. Location of group measurement point and any field compressors and line heaters. Tie-in location of other gas systems. Status of nonproducing wells. Dates of last well tests, if applicable. Check flaring and venting records. Check where fuel gas comes from and where sales gas is delivered. Check how water is disposed of. Note if any liquids are recovered at compressor stations and how they are handledrecombined or trucked out. Record all test meter readings taken by the operation personnel if applicable. Record the time off for the well test(s) witnessed. It is important to take detailed notes before you leave the lease when your observations are fresh in your mind. Go over your notes and elaborate if necessary. Write down any points you may have missed or points requiring further clarification. Check to ensure that the battery type code matches with what is going on in the field. Check for wet and dry gas metering producing to the same battery. Wet metering requires proration from a group measurement point. If dry metering is mixed with wet metering, all the dry volumes have to be subtracted from the group meter before proration. OGCR, Section 14.040, does not permit metering by difference unless special approval is given by the ERCB. Check for oil wells tied into a gas battery. Directive 60 requires that oil well (associated) gas tying into a gas battery be reported separately under a different battery code and vice versa.

5 Records Review All of the following reviews are to be completed in the office after the field trip.

Records Request Attach a cover letter to the Data Request Sheet (see samples in Appendix F-2): Address it, by name if possible, to the Production Superintendent/Operations

Manager level.


Identify the battery name, legal land description, operator code, facility code, and licence or approval numbers, if applicable.

Allow the licensee a reasonable time to assemble the information requested. Consider

the size and complexity of the facility. Choose a due date at least 30 days from the time of the request.

Follow up your request letter verbally to check if it was received and to ensure the

information will be filed within a reasonable time. Data Request Sheet Request all field and accounting records relevant to the facility being audited, as listed on the Data Request Sheet in Appendix F-2. You may also wish to request additional information not covered on the request sheet. Receipts of Records Review the contents and request any information not submitted. Ask for an explanation for any requested item that the licensee is unable to provide.

5.1 Oil Batteries 5.1.1 Oil Battery Production Reports Monthly volumetric submission amendments must be completed, as outlined in Directive 7, through the Petroleum Registry. Request amendments if significant and correctable reporting errors are noted. You may use the following criteria to determine amendment requirements for most cases: Any error that results in a change in the total battery production must be corrected,

regardless of the magnitude of the change, since the error will affect the production for all the wells in the battery.

Any error that results in a change in the estimated and/or actual oil production at a

well in excess of a predetermined criteria may warrant an amendment. The graph of amendment criteria (see Figure 1) can be used as baseline data when production volume amendments are being considered.

5.1.2 Oil Battery Equipment Measurement equipment is unsatisfactory if it does not meet the ERCB measurement requirements or if additional equipment is required. See Directive 64: Facility Inspection Manual Oil and Gas Conservation Act and Regulations Oil Sands Conservation Act and Regulations Appendices D-1 and F-3.


Figure 1. Criteria for requesting amendments; permissible change before amending on a per well basis


Central Facility/Satellites Do the group vessels and tankage provide adequate separation of oil, gas, and water? Are enough test vessels installed to comfortably meet the minimum test frequency (see ID 94-1 and Schedule 16 of OGCR; ID 91-3 for heavy oil)? Are test vessels and test tanks correctly sized for the flow conditions encountered? Test tank diameter sizing calculation is summarized in Appendix A-3. Are gas wells associated with oil battery? Directive 60 requires gas wells flowing to oil batteries to have separate battery codes and special approval from ERCB. Field Header/Common Flow Lines Can the required purge duration and test frequencies be met with existing equipment? Use the total fluid flow rate of the producing well and the test line capacity to

calculate the minimum purge time required. Example: Calculate the minimum purge time required for the following common test

line:

- Line dimensions = 1500 m length, 88.9 mm OD pipe, 3.2 mm wall thickness - Two wells tied in

Well #1 flow rate = 5.5 m3 oil/d, 12.0 m3 water/d Well #2 flow rate = 7.2 m3 oil/d, 18.9 m3 water/d Step 1

d = (88.9 3.2 x 2)/1000 = 0.0825 m Test line capacity = 3.1415926 x d2 x length / 4 = 3.1415926 x (0.0825)2 x 1500 /4 = 8.02 m3

Step 2 Purge time required = Test line capacity (m3)/ Well flow rate (m3/h) Well #1 total fluid flow rate = (5.5 m 3 + 12.0 m3) /24 h

= 0.729 m3/h

Purge time required = 8.02 m3/ 0.729 m3/h = 11.00 h Well #2 Total fluid flow rate = (7.2 m3+ 18.9 m3) /24 h = 1.088 m3/h Purge time required = 8.02 m3/ 1.088 m3/h)

= 7.37 h

Therefore the minimum purge time required for Well #1 is 11 hours and for Well #2 is 7.5 hours.


Fluid Samplers All Meters Are sampling devices operating as per manufacturers specification? (See Appendix C-1.) Oil Meters Determine if additional meters are required. (See Central Facility Satellites on previous page.) Is downstream valve snap acting or throttling? (See OGCR, Section 14.080.) Ensure that the meters used are appropriate for the flow conditions encountered. (See Appendix A-1.) 5.1.3 Oil Battery Procedures and Records Refer to your field notes, operation personnels field records, and gas charts to complete this section. Determine if the procedures the operation personnel demonstrated and described are consistent with the recorded data. Proration Tests Check all proration tests. Are the minimum proration test duration and frequency requirements met? Is the test frequency and duration adequate to ensure a representative test? Some wells may require longer test duration for a representative test, such as 48 or 72 hours. Does the duration match the on/off times, accounting worksheets, field records, etc.? Are common test lines and test vessels adequately purged? Where there is more than one well on a common flow line, does the operation personnel cascade test or shut one well in at a time to test? Check for approval to conduct cascade testing (see Appendix A-5). Do the test and group lines operate within an acceptable pressure difference (200 kPa maximum)? Are wells retested within a reasonable time when production conditions are changed (e.g., the initial production from a well after shut-in or workover)? Wells should be retested as soon as practical after conditions change. Are all valid well tests recorded, submitted, and used? Some reasons why well tests might be rejected are insufficient data due to equipment failure during a test insufficient purge time allowed well flow conditions changed during a test (e.g., choke setting, pump stroke, etc.) battery upset or emergency shutdown production/BS&W fluctuation


Sort test data reports (usually gas charts) by test vessel and arrange in chronological order. A continuous test in excess of 24 hours is to be counted as one test. The test date is the day when the test starts. Check meter readings and on/off times to ensure that they correspond from test to test. Look for purge time and misrun tests. Volumes are to be measured to the nearest 0.01 m3 and rounded to the nearest 0.1 m3. Compare the test meter readings witnessed during the field inspection to what are submitted for review. Are well tests spaced evenly throughout the month? What is the status of nonproducing wells? For heavy oil well testing, see ID 91-3, Section 4.2. Fluid Sampling and BS&W Determination Samples should be sufficiently large to get a representative sample (see Appendix C-3). Larger samples are required for higher water cut and large volume producers. Is sampling conducted as outlined in OGCR, Section 14.150? If water content is greater than 10%, use proportional sampler and analyze the sample accurately or use product analyzer. If less than 10%, you may determine water content by centrifuging two well-spaced samples taken during each test and averaging the results or by the above methods. The samples should be taken in close proximity to the measurement point. The centrifuge method is acceptable for samples containing less than 10% water. The graduated cylinder method should be used for all other samples. (See Appendix C-3.) Mason jars with tape attached are not acceptable for determining BS&W. Trucked Production Is volume of each outside load measured and reported to the nearest 0.1 m3? Is the method of sampling emulsion satisfactory? (See Appendix C-1 and IL 90-6.) If loads are split by transferring free water to the water tanks and the emulsion to another tank, each part must be accurately measured. Meter Calibrations Calibrations must be done in accordance with the following:

Oil meters Test: OGCR, Section 14.110 Group: OGCR, Section14.120 Gas meters ID 90-2 Condensate meters OGCR, Section 14.090 (2) (3) Water meters OGCR, Section 14.140 (3) (4)

Check for up-to-date calibration tags and records.


Shop calibration of liquid meters (density less than 920 kg/m3) is permissible when the average liquid rate (i.e., total fluid for a two-phase separator and liquid in oil leg for three-phase) of all wells being tested through the meter is less than 2.0 m3/d and no well exceeds 4.0 m3/d. For densities at 920 kg/m3 or greater, shop calibration is permissible under ID 91-3, Section 4.4. Field Records Look for completeness and accuracy. All field measurement and pertinent operational data must be recorded and retained on file for 12 months, in accordance with OGCR, Section 12.170, except for heavy oil, which requires 18 months of records to be on file, in accordance with the OSCR, Section 17. Check field estimates, calculations, and summary reports for blowdown, flared and vented volumes, stock tank vapour estimates, lease fuel estimates, etc. Errors in calculations or data not affecting the production report volumes should not be recorded as a deficiency (daily prorations, etc.). Tank Gauging Is linear metre to cubic metre conversion satisfactory? Are gauging tables used? Is each tank, including test or equalized tanks, gauged to the requirement of Appendix A-2? Gas Chart Documentation See Appendix D. Load Fluid See Directive 7, appendix on Load Fluid. 5.1.4 Oil Battery Accounting Production Summary Review the general accounting formula for the facility (i.e., how the measurement, estimates, receipts, deliveries, and inventories are added and subtracted to determine the numbers entered on the production reports). Review the flow diagram to ensure that the accounting formula matches the physical facility. Are measurement and estimate points included? Is well status correct? Are all estimates included? Are receipts and deliveries determined satisfactorily?


Are inventories determined satisfactorily? Is shrinkage accounted for? Are all applicable temperature and density corrections applied? Are associated gas wells reported on their own production reports? How is gas-lift gas metered and reported? Production hours for wells with intermittent timers, pump-off controls, plunger lifts, etc., that are operating normally and as designed are to be considered on production even when the wells are not pumping. Physical well shut-ins and emergency shutdowns (ESDs) are considered down time. The operation personnel has to make a judgement call based on the operating environment in other situations where the wells are not shut in but may or may not have production. Pipeline Tickets These include LACT meter, gauge sheet, and truck terminal tickets. Are meter factors, BS&W, and temperature and density correction factors applied? Compare the meter readings or gauge readings with the field inspection results. Gas Chart Reading The integrator traces must closely follow the chart pen traces. Verify the accuracy of the average static, differential, and temperature readings on the chart reading summary. Send the chart out for rereading if necessary. Confirm the accuracy of the chart information (temperature, orifice size, run size, chart drive speed, on/off times, and gas density) entered on the chart-reading summary. The integrator operator must not estimate missing pen traces unless there are instructions from the operation personnel to do so. Integrators record flowing time and test duration. Do not prorate gas summary volumes to 24 hours. See Appendix D-1 to D-4 for more information on gas charts. Gas Volume Calculation For orifice meters, gas volume must be calculated as outlined in AGA3 and IL 87-1.

(See Appendix G-1 for metric conversion factors.) PD Meter Measuring GasMeter readings must be corrected to base temperature

and pressure conditions, including the compressibility factor. (See Appendix B-1.)


Unmetered Gas Estimates There could be routine flaring and/or venting of treater gas or other unmetered gas streams. Estimate these using the same methods as outlined in the GOR below. Or if there is emergency flaring or venting where meters are bypassed or flare meters are overranged, estimate the volume from the facility gas flow balance or refer to the Canadian Association of Petroleum Producers (CAPP) Directive for Estimation of Flaring and Venting Volumes from Upstream Oil and Gas Facilities. Ensure that Directive 60 requirements are met for reporting of flaring and venting. Pilot or dilution gas for flare is to be reported as fuel. Lease Fuel Estimates

Consider all gas source points and fuel users, including satellite gas taps, casing head gas, pump motors, instrument gas, building heaters, heated tanks, treaters, line heaters, FWKOs, flare pilots, etc. Fuel usage greater than 500 m3/d must be measured in accordance with Directive 64, Section 1.4 (b). Estimates for less than 500 m3/d usage must be based on quantifiable data, such as manufacturers specifications or previous measurement of fuel rates. Estimating fuel consumption at treaters and FWKOs is discussed in Appendix E-1.

Gas-Oil Ratio (GOR) Licensees are no longer required to formally apply for Gas Measurement Exemption. The requirement to annually test the gas rates and update the GOR remains in effect. Review the most recent GOR test results. See requirements in Section 15.140(3) of OGCR. Ensure that the gas-in-solution correction (below) and upstream lease fuel (e.g., casinghead gas) are applied to the test gas volume used to determine the GOR. Check calculations. GOR applies only to wells and facilities producing gas less than 500 m3 (0.5 103 m3) per day for conventional oil and up to 2.0 103 m3/d for heavy oil (see IL 91-9). See Directive 7, appendix on Crude Oil/Bitumen Battery, Exemptions from Gas Measurement. Estimated Production Estimated production must be calculated using the test-to-test method outlined in Directive 7, appendix on Crude Oil/Bitumen Battery, Prorated Production. Ensure that the test(s) you witnessed is used and that it is consistent with the licensees valid test criteria. A computer program can be used to perform this calculation. Spot check the arithmetic for several wells and verify all entry data.


If the calculation is done by hand, complete the Monthly Proration Test Worksheet (see example in Directive 7) to verify the estimates. All valid well tests must be used. Consecutive-day tests should be entered as one extended test unless the first day(s) are measurements of flush production, stabilization period, etc. No well can be recorded as measured if the production is flow-lined to a proration battery unless this is the only well producing to the battery for the month. However, there can be prorated and measured production in the same month, such as a single-well battery trucked in to the main battery for part of the month and then flow-lined. The actual test duration, to the nearest 15 minutes, must be used to determine estimated production rates. Test gas volume must include an estimate of gas-in-solution with oil (see Gas-in-Solution section below). Truck Tickets and Summary Are all volumes on the tickets accounted for in the production records? Are BS&W splits and other corrections correctly calculated? Is the trucked-in emulsion (oil) from the same pool as the flow-lined wells? Did the density change from load to load? Shrinkage correction is required if there is blending of emulsion (oil) before measurement and the densities differ by more than 40 kg/m3. Are there open and close gauge or meter readings? Is the decimal format correct? Check for split loads. (See split loads policy in Appendix A-4.) Are the requirements outlined in IL 90-6 and IL 92-8 adhered to? Gas Density Gas density must be updated in accordance with Directive 49: Gas Density Measurement Frequency. Density will vary with process temperature and pressure. Therefore, density must be measured at each orifice metering point in accordance with Directive 49. Gas-in-Solution Estimates Gas-in-solution is the volume of gas liberated from the oil as the pressure is reduced. It is sometimes referred to as test-to-group correction. The gas-in-solution correction factor will be reported to standard conditions in cubic metres of gas per cubic metre of oil per kilopascal of pressure drop.


The number of stages of separation and the conditions at each stage will affect the volume of gas liberated. A correction factor is required for each test vessel and for each unique test temperature/pressure situation. This correction is imperative for low GOR pools and multipool batteries and when testing at high pressure. Gas-in-solution volumes must be added to the group measurement volume, unless a metered vapour recovery unit(s) (VRU) is in use. Gas-in-solution volumes for the well on test must be added to the well test gas volumes based on pressure drop and oil volume. See Appendix E-2 for details. Injection Summary Check the accounting formula used to determine the receipt, delivery, and injection volumes reported on the monthly volumetric submissions for Injection/Disposal. Ensure that measured volumes are used and metering differences are reported, if any.

5.2 Gas Batteries 5.2.1 Gas Battery Production Reports Monthly volumetric submissions must be completed, as outlined in Directive 7, through the Petroleum Registry. Request amendments if significant and correctable reporting errors are noted: Any error that results in a change in the total battery production should be corrected,

regardless of the magnitude of the change, since the error will affect the production for all the wells in the battery.

5.2.2 Gas Battery Equipment Measurement equipment is unsatisfactory if it does not meet the ERCB measurement requirements or if additional equipment is required. See Directive 64: Facility Inspection Manual Oil and Gas Conservation Act and Regulations Oil Sands Conservation Act and Regulations Appendix D-1: Orifice Meter Inspection Guidelines Appendix F-3: Facility Check Sheet ID 90-2: Gas Meter Calibration


5.2.3 Gas Battery Procedures and Records Refer to your field notes, operation personnels field records, and the gas charts to complete this section. Determine if the procedures the operation personnel demonstrated and described are consistent with the recorded data. Production Tests Production tests can be used in place of continuous measurement for southeast Alberta gas proration batteries and other ERCB-approved gas proration batteries. Testing is also required for effluent meter correction (ECF) and the WGR, if applicable, and is performed in accordance with Directive 4, unless special approval has been obtained from the ERCB Compliance and Operations Branch for relaxing of the testing frequency. For effluent measurement, ensure that proper procedures are followed. See IL 93-10; Directive 7, Appendices 10 and 11; and Directive 4. BS&W Determination See Appendix C-3. Trucked Production Volume of each receipt load must be measured and reported to the nearest 0.1 m3. If condensate and water are trucked from the wells, where are they delivered? If loads are split by transferring free water to the water tanks and the condensate to another tank, each part must be accurately measured. Meter Calibrations Oil meters Test: OGCR, Section 14.110 Group: OGCR, Section 14.120 Gas meters ID 90-2 Condensate meters OGCR, Section 14.090 (2) (3) Water meters OGCR, Section 14.140 (3) (4) Check for up-to-date calibration tags and records. Shop calibration of condensate meters is permissible when the condensate rate is less than 2.0 m3 per day or less than 3.0 m3 per day and the gas equivalent volume of the condensate is less than 3% of the measured gas volume. Field Records Look for completeness and accuracy. All field measurement and pertinent operational data must be recorded and retained on file for one year, in accordance with OGCR, Section 12.170.


Check field estimates, calculations, and summary reports for blowdown, flared and vented volumes, stock tank vapour estimates, lease fuel estimates, etc. Errors in calculations or data not affecting the production report volumes should not be recorded as a deficiency. Tank Gauging Is the procedure satisfactory? Is linear metre to cubic metre conversion (strapping tables) satisfactory? Is the correct gauge table being used? Each tank, including equalized tanks, must be gauged to the requirements in Appendix A-2. Gas Chart Documentation See Appendix D-1 to D-4. Is blowdown recorded on chart? Fuel, flaring and venting gasAre pressure and temperature recorded? Are they measured? Load Fluid See Directive 7, appendix on Load Fluid. 5.2.4 Gas Battery Accounting Production Summary Review the general accounting formula for the facility (i.e., how the measurement, estimates, receipts, deliveries, and inventories are added and subtracted to determine the numbers entered on the production reports). Review the flow diagram to ensure that the accounting formula is correct. Are measurement and estimate points included? Is well status correct? Is gas well producing oil, as opposed to condensate? Are all estimates included? Are receipts and deliveries determined satisfactorily? Are inventories determined satisfactorily? Is shrinkage accounted for? How is liquid handled? If it is trucked out from tanks, where is it delivered? Or is it metered and recombined or ECF used?


Wells with intermittent flow controls, plunger lifts, etc., that are operating normally as designed are considered on production even when the wells are not flowing. Physical well shut-in and ESDs are considered down time. The operation personnel has to make a judgement call based on the operating environment in other situations where the wells are not shut in but may or may not have production. Pipeline Tickets Are meter factors, BS&W, and temperature and density correction factors applied? Gas Chart Reading The integrator traces must closely follow the chart pen traces. Verify the accuracy of the average static, differential, and temperature readings on the chart-reading summary. Send the chart out for reread if necessary. Confirm the accuracy of the chart information (temperature, orifice size, run size, chart drive speed, on/off times, and gas density) entered on the chart-reading summary. The integrator operator must not estimate missing pen traces unless there are instructions from the operation personnel to do so. Integrators record flowing time and test duration. Do not prorate gas summary volumes to 24 hours. See Appendix D-1 to D-4 for more information on gas charts. Gas Volume Calculation For orifice meters, gas volume must be calculated as outlined in AGA3 and IL 87-1. See Appendix G-1 for metric conversion factors. Positive displacement (PD) meter measuring gasMeter readings must be corrected to base temperature and pressure conditions, including the compressibility factor. (See Appendix B-1.) Acid gas volumesee Appendix B-2. Unmetered Gas Estimates Consider all gas source points and fuel users, including pump motors, instrument gas, building heaters, heated tanks, line heaters, FWKOs, and flare pilots. Estimates must be based on quantifiable data, such as manufacturers specifications or previous measurement of fuel rates. See Appendix E-1. Unmetered flare and vent gas estimateWhere there is flaring or venting when meters are not present or when bypassed or if flare meters are overranged, estimate the volume from the facility gas flow balance or refer to the CAPP Guide for Estimation of Flaring


and Venting Volumes from Upstream Oil and Gas Facilities. Ensure that Directive 60 requirements are met for reporting of flaring and venting. Report pilot or dilution gas for flare as fuel. Estimated Production Are estimated volumes calculated correctly? Is meter factor applied to liquid meter volumes? Is water volume determination satisfactory? No well can be reported as measured if the production is prorated unless approved by the ERCB. This is not required to be reported to the Petroleum Registry. However, look out for mixed measurement: measured gas in proration battery or measured gas mixed with effluent measurement. This requires special approval from the ERCB Compliance and Operations Branch because of measurement by difference. See IL 93-10 and Directive 7, Appendix 10. Truck Tickets and Summary Are all tickets accounted for? Are there open and close gauge or meter readings? The gauge readings should be there if they are taken. Is the decimal format correct? Identify delivery type (disposal, sale, etc.). Gas Density Gas density must be updated in accordance with Directive 49: Gas Density Measurement Frequency. Density varies with process temperature and pressure. Therefore, density must be measured at each orifice metering point, in accordance with Directive 49. Gas Equivalent Calculation NGL and condensate are normally stored and measured in a liquid state; however, they must be reported on the production reports (except gas processing plant products monthly volumetric submissions or production monthly volumetric submissions, as well as disposition monthly volumetric submissions if trucked out) as a gas equivalent volume (103 m3). A conversion factor can be calculated from a compositional fluid analysis. The three methods of calculating gas equivalent factors are outlined in Appendix E-3.


The fluid analysis used to derive the factor must be updated annually, unless gas production is 16.9 103 m3/d or less, when it must be updated once every two years. (See OGCR, Section 11.080, and Directive 49.) Injection Summary Check the accounting formula used to determine the receipt, delivery, and injection volumes reported on the injection/disposal monthly volumetric submission. Ensure that measured volumes are used and metering differences are reported, if any.

5.3 Audit Results Record the inspection result for each category inspected and total the overall result. The original stays in the audit file. Give a copy to the Production Audit technician for statistical use.


Appendix A Liquid Measurement

A-1 Recommended Rates and Pressure Drops for Liquid Meters When evaluating fluid measurement systems, it is important to first determine if the control or dump valve is a snap-acting type valve. By having snap-acting control, as well as having a properly designed separator system, the meter will immediately get up into the recommended operating range of approximately 30% to 70% of the meter capacity. Each meter manufacturer guarantees a specific accuracy range for a given meter provided that the recommended flow rates and pressure drops are adhered to. The following two tables and chart list several meters currently in service for oilfield production measurement. The manufacturers recommended flow rates and pressure drops are indicated. If the meter is not on the list, record the meter type, size, model, and serial number and call the manufacturer or local representative for that information. The following procedure can be used to check if a meter has been sized to operate within the manufacturers specifications: Record the meters opening and closing readings. Watch the dump valve when it is actuated to determine if it is snap-acting. (The valve

should open fully in 3 to 4 seconds.) Record the time required for the dump valve to open and close completely (referred

to as duty-cycle). From the duty-cycle and the meter readings, a 10-second flow rate can be

determined. Volume (L) = [ Closing meter reading (m3) Opening meter reading (m3) ] x

1000 L/m3 Flow rate (L/10s) = [Volume (L) / Time (s)] x 10 Flow rate (LPM) = [Volume (L) / Time (s)] x 60 Compare your result to the manufacturers recommended 10-second flow rates. Watch the dump valve close to determine if the valve leaks. (The meter will continue

to spin after the leaking valve is closed.)


Table 1. Positive Displacement Meters

Type Size

(inches) Flow rate (m3/day)

Oil and water pressure drop

(psi) Min - Max

Condensate pressure drop

Min Max

Flow rate (L/10 sec) Min - Max

AO Smith

1 2 2 3

133.5 686 305 - 1525

.02 2.5 .02 4.5

Not recommended

15 79.5

35.5 176.5 Mock & Floco 500# 500 2500# 2500 5000# 2500#

1 2

3 1 2

32 326 49 490 32 326 32 - 326

1.0 15.0 .5 6.0

1.5 15.0 1.0 15.0

3 15 3 15 3 15 3 - 15

3.7 38.0 5.6 56.0 3.7 38.0 3.7 38.0

Flotrac

1 306 1 - 380

23 476

8 - 81

2.5 50.0 1.5 45.0

2.5 50.0 1.5 45.0

2.6 55.0 1.0 9.0

Brooks (Red) (Black)

1 793 1 792

26 286 7.9 - 108

1.0 20.0 1.0 5.0

3 15 1 15

3.0 - 33 .1 13

Neptune

5/8 1

1 2

11 109 16 164 27 271 55 545 87 - 872

Not available

Not recommended

1 12 2 18 3 31 6 63

10 100


Table 2. Turbines

METER METERAVERAGE K-

FACTORAVERAGE K-

FACTOR FLOW RATE (GPM) FLOW RATE (BPD) FLOW RATE (LPM) FLOW RATE (m3 PD)

TYPE SIZE (pulses/gal) (pulses/m3) Min Max Min Max Min Max Min MaxBlancett 3/8" 15364 4059169 0.3 3.00 10.3 102.9 1.14 11.36 1.5 16.4

1/2" 11145 2944509 0.75 7.50 25.7 257.1 2.84 28.39 4.1 40.93/4" 3033 801309 2.0 15.0 68.6 514.3 7.57 56.73 10.9 81.87/8" 3047 805007 3.0 30. 102.9 1328.6 11.36 113.55 16.4 163.51" 847.04 223788 5.0 50.0 171 1714 18.93 189.25 27.3 272.5

1-1/2" & 2" 318.42 84027 15 180 514 5171 57 681 81.8 981.12" 46.23 12214 40 400 1371 13714 151 1514 218.0 2180.23" 51.46 13596 60 600 2057 20581 227 2271 327.0 3270.24" 30.13 7960 100 1200 3429 41143 379 4542 545.0 6540.56" 7371 1947 200 2500 6857 85714 757 9463 1090.1 13626.08" 3014 796 250 3500 8571 120000 946 13248 1362.6 19076.510" 1643 434 500 5000 17143 171429 1893 18925 2725.2 27252.1

Cliff Mock 1" 860.02 227218 5.0 50.0 171 1714 18.93 189.25 27.3 272.51-1/2" 325.01 85867 15 180 514 6171 57 681 81.8 981.1

2" 53.00 14003 40 400 1371 13714 151 1514 218.0 2180.23" 56.00 14796 50 600 2057 20571 227 2271 327.0 3270.24" 29.00 7662 600 1200 3429 41143 379 4542 545.0 5540.5

Daniels 3/4" 940.42 248458 3.9 28.8 132.1 987.6 14.58 109.03 21.0 157.01" 570.25 150660 6.0 60.0 206 2057 22.71 227.08 32.7 327.0

1-1/2" 140.05 37000 14.9 129.9 510 4454 56 492 81.0 708.02" 115.05 30396 25.0 224.8 656 7706 94 851 136.0 1225.0

Halliburton 3/8" 20001 5234137 0.30 3.00 10.3 102.9 1.14 11.36 1.6 16.41/2" 13000 3434689 0.75 7.50 25.7 257.1 2.84 28.39 4.1 40.93/4" 3000 792621 2.0 15.0 68.6 514.3 7.57 56.78 10.9 81.87/8" 1601 423000 3.0 30.0 102.9 1028.6 11.36 113.55 16.4 153.51" 920.02 243070 5.0 50.0 171 1714 18.93 169.25 27.3 272.5

1-1/2" 330.01 87177 15 180 514 6171 57 681 81.8 981.12" 55.00 14531 40 400 1371 13714 151 1514 218.0 2180.23" 57.00 15060 60 600 2057 20571 227 2271 327.0 3270.24" 29.00 7662 100 1200 3429 41143 379 4542 545.0 6540.56" 7.37 1947 200 2500 6857 85714 757 9463 1090.1 13526.08" 3.01 796 350 3500 12000 120000 1325 13248 1907.6 19076.5

Hydril 1/2" 12000 3170482 0.72 7.28 25 250 2.71 27.57 3.9 39.73/4" 3200 845462 2.0 15.0 66 515 7.50 56.81 10.8 81.81" 860.03 253639 5.0 49.5 170 1698 18.75 187.50 27.0 270.0

1-1/2" 320.01 84546 15.0 174.8 515 5995 58.81 661.80 81.8 9532" 213.01 56276 37.8 378.9 1296 12990 143.06 1434.02 206 2065

ITT Barton 3/4" 2885 762255 2.5 30.0 36 1030 9.51 113.68 13.7 163.71" 1048 276948 6.0 75.1 205 2575 22.64 284.3 32.6 409.4

1-1/2" 419 110779 15.0 180.3 515 6182 56.87 682.50 81.9 982.82" 138 36399 25.0 300.5 659 10302 94.79 1137.29 135.5 1637.73" 41 10814 55.1 561.1 1868 22666 208.47 2502.21 300.2 3603.2

Natco 3/4" LF 4548 1201512 1.32 13.12 45 450 5.00 49.65 7.2 71.53/4" 1875 495388 3.21 23.04 110 790 12.15 87.22 17.5 125.61" 938 247826 6.4 63.9 220 2190 24.31 241.74 35 348.1

1-1/2" 345 91088 17.5 175.0 600 6001 56.25 662.50 95.4 9542" 180 47557 33.0 289.9 1131 9939 127.86 1097.22 179.8 1580

Tejas/ 3/4" 2101 555066 2.92 29.17 100 1000 11.04 11.42 15.9 159Camco 1" 700 185022 8.8 87.5 300 2999 35.12 331.04 47.7 476.7

1-1/2" 350 92511 17.4 174.8 598 5995 55.97 661.80 95 9532" 220 58149 29.2 291.5 1000 9996 110.35 1103.47 58.9 1589


Chart 1. Flow Curves for 1" and 2" Floco Meters


A-2 Tank Gauging Procedure There are two basic methods for obtaining manual tank gauge readings: 1) Innage gauge the depth of liquid in a tank is measured from the surface of the liquid

to the tank bottom or to a fixed datum plate. (The bob and tape must be lowered so that the bob just touches the tank bottom. Lowering the bob too far will cause incorrect gauge readings.)

2) Outage gauge the distance from a reference point at the top of the tank to the

surface of the liquid is measured. This gauge is then subtracted from the full height gauge (from the same reference point) of the tank to determine the liquid content.

Either of the above manual tank gauging methods is acceptable for gauging crude oil storage tanks. Ensure that the correct gauge table is used to calculate the liquid volume, because two tanks of the same volume could have different tank diameters. See Directive 017, section 14.7 for requirements (April 18, 2011) For manual custody transfer gauging: For tanks greater than 160 m3 (1000 bbl), two consecutive readings to be within a

range of 3 mm (1/8 in.) of each other are required; use the average of the two readings.

For tanks 160 m3 (1000 bbl) or less, one reading is acceptable. All readings must be

determined to the nearest 3 mm (1/8 in.). For noncustody transfer gauging, such as inventory control, one reading on the gauge tape is acceptable for all tanks and must be determined to the nearest 3 mm (1/8 in.). Note that the gauge tape should stay in contact with the tank hatch while lowering and raising the bob in the tank. This will ensure that static charge is not allowed to build up while the tape is being used. For custody transfer or truck receipts, the operation personnel should ensure that the tank level is not changing when the readings are taken (this may require shutting in the tank before gauging). For production tanks, no shut-in is required when gauging the tank.

For all nonmanual or automatic tank gauging systems, one reading on the instrument is acceptable and must be determined to the nearest 3 mm (1/8 in.). Ensure that the gauging system is operating freely, without obstruction, before the reading is taken. Eye-level readings are required for reading gauge boards. Gauge board markings should be to the nearest 3 mm (1/8 inch). The automatic gauging system should be calibrated in accordance with API MPMS Chapter 3.1B.4 calibration procedures, except for the frequency of calibration. The gauging system must be calibrated before being put into service and on a yearly basis thereafter.


A-3 Well Test Tank Diameter Sizing Guidelines Tank gauging is subject to errors or uncertainty in the reading of the tape (in and out), as well as in the accuracy of the tape itself (in and out). The error in total volume measurement can be minimized by maximizing the height of the fluid column being gauged. Given a specified tank diameter, uncertainty at 1%, and gauge reading to the nearest 1/8 inch or 3 mm according to Appendix A-2, the required test volume can be estimated. Conversely, knowing the rates of the wells (i.e., test volume), the required tank diameter can be calculated. See Directive 017, section 12.3.4 and 14.7.3 for requirements (April 18, 2011) To meet accuracy requirements for total test fluid measurement, the minimum test fluid volume or maximum tank diameter should be determined as follows:

V >= a x d2 OR d = < (V/a)1/2

Where: V = test volume in m3 d = test tank diameter in metres a = accuracy coefficient = 0.39 for 1.0% uncertainty

There is some flexibility when applying this rule of thumb. Practicality suggests that requirements for low-productivity wells might be less than the guidelines suggest. Note that test tank volumes must also be temperature corrected.


A-4 Split Loads Guideline - Replaced by Directive f017, section 10.3.5 (April 18, 2011)

A split load is defined as existing when a truck takes on partial loads from more than one well or battery in a single trip or when load oil is delivered to more than one receipt point or wells. Allowed: - Single-well oil battery

- Gas wells with condensate tanksless than 2.0 m3 liquids per day production - Blending of heavy oil and condensate - Load oilfor well servicing only; load up from a single source only

Not allowed: - Multiwell batteries - Gas wells with greater than 2.0 m3 liquids per day production

Requirements: Densities must be similar (within 40 kg/m3); if they are not, blending tables are required to calculate shrinkage. The shrinkage volume is to be prorated back to each battery on a volumetric basis.

Measurement: Volume from each well or source must be measured at the time of loading onto the truck (or off loading from the truck for load oil) by one of the methods below:

i) gauging the battery lease tank; ii) gauging the truck tank (not allowed for density difference over

40 kg/m3 for any oils or emulsions); or iii) truck-mounted metercalibrated minimum once every 6

months. Calibrated gauge tables are required for methods (i) and (ii) above.

Sampling: Fluid from each single-well oil battery must be sampled to determine the BS&W and the oil/water volumes. The truck driver is to collect the samples by taking at least 3 well-spaced grab samples during the loading period. The operation personnel of the unloading location is to determine the BS&W from the samples taken. For load oil, the BS&W should be determined at the loading source.

Records: The truck tickets must show the individual load volumes, as well as the total volume at delivery (receipt) point, supported by opening and closing gauge or meter readings.

Accounting: For battery emulsions, the total load is to be measured and sampled

at the unloading location and prorated to each of the wells based on the measured loading volumes and BS&W from each of the wells. For load oil, the initial volume must be measured at the loading source and prorated to each delivery point based on the measured volume delivered to each well.


A-5 Cascade Testing When a prorated oil well has low gas production such that it cannot properly operate test equipment, a licensee may test two oil wells simultaneouslycascade testthrough the same test separator. See Directive 017, section 6.7 for requirements. (April 18, 2011) In such cases, the following procedure must be followed: 1) Establish accurate oil, gas, and water production volumes for a high gas producing oil

well by testing it individually through the test separator for a period of 24 hours or longer for a representative test.

2) Conduct a representative test for both the high gas producing oil well and low gas

producing oil well together through the same test separator for a period of 24 hours or longer immediately after testing the high gas producing well, allowing time for stabilization. (The testing sequence may be reversed, with testing the combined wells first.)

3) The operating condition of both wells must not be changed. If it is, a new set of tests is

required. 4) Total test oil, gas, and water volumes determined for the cascade test minus the test oil,

gas, and water volumes for the high gas producing oil well will be the test volumes for the low gas producing well.

5) It is recommended that both wells have similar BS&W percentages. If any of the

calculated oil, gas, or water volumes for the low gas producing oil well is negative, the tests are not representative and both tests must be repeated.

The use of cascade testing does not require special approval from the ERCB. Common Flow Line: Cascade testing is allowed for common flow-lined wells, provided that they meet the above conditions for cascade testing. However, the combined (cascade) test must be conducted first, and then the low gas producing well must be shut in to test the high gas producing well, allowing sufficient purging and stabilization time. Note that the use of common flow lines requires special approval from the ERCB, except for heavy oil if exempted in ID 91-3. Example Well A = High gas producing Well B = Low gas producing Test Results

Well Test date Oil (m3) Gas (103 m3) Water (m3) Well A+B July 4 80.0 20.0 20.0 Well A July 5 50.0 19.0 12.0 Well B = (Well A+B - Well A) July 4 30.0 1.0 8.0



Appendix B Gas Measurement

B-1 Gas Volume Calculation

Orifice Meters: Gas volumes are calculated from gas chart readings using either one of the following formulas.

AGA 3 (1985) AGA3 (1990) Q (Mcf/h) = C x (hw x Pf) / 1000 Q (Mcf/h) = N1 x Cd x Ev x Y1 x d2 x (hw x Pf1 x

Zs / Gr / Tf / Zf1) x Fpb x Ftb x (Zb / Zs)

Where: Where: C = Fb x Fr x Y x Fpb x Ftb x Ftf x Fg x Fpv x Fa N1 = Unit conversion factor (7.70961 for

imperial units) Q = Volumetric flow at base conditions Cd = Coefficient of discharge Fb = Basic orifice factor Ev = Velocity of approach factor Fr = Reynolds number factor Y1 = Upstream expansion factor Y = Expansion factor d = Orifice plate bore diameter at flowing

temperature Fpb = Pressure base factor Pf1 = Absolute upstream static pressure Ftb = Temperature base factor Ftf = Flowing temperature factor

Zs = Compressibility of gas at standard conditions

Fg = Specific gravity factor Zb = Compressibility of gas at base conditions Fpv = Supercompressibility factor

Zf1 = Compressibility of gas at upstream flowing conditions

Fa = Orifice thermal expansion factor Gr = Real gas specific gravity Hw = Inches of water differential from the chart Tf = Absolute temperature at flowing conditions Pf = Absolute static pressure

Multiply Q by the number of flowing hours to obtain the total volume for the period. Metric Conversion for Volume

From (MCF) To (103 m3) Fpb, Ftb values Conversion factor @ 101.325 kPa, 15C @ 101.325 kPa, 15C Fpb = 1.0023

Ftb = 0.9981 0.02831685

@ 14.65 psia, 60F @ 101.325 kPa, 15C Fpb = 1.0055 Ftb = 1.0000

0.02817399

Other Meters: Gas volume for positive displacement meters, turbine meters, and vortex meters can be calculated by using the following formula: Q = CR x Pf / Pb x Tb / Tf x 1/ Z Where:

CR = Meter counter reading difference Pf = Flowing pressure (absolute) Pb = Base pressure (absolute) Tf = Flowing temperature (absolute) Tb = Base temperature (absolute) 1/Z = Compressibility factor at Pf (from AGA8, Redlich-Kwong, etc., based on

sample analysis; see IL 87-1)

Note that there might be a meter factor to be applied to the CR. In some cases, meters have built-in temperature and/or pressure correction. If so, the temperature and/or pressure correction portion of the formula can be ignored. Use the same absolute units for Pf and Pb, Tb, and Tf. Gas density is not required to perform the above corrections. However, a gas sample analysis is required to calculate the compressibility factor for varying pressures and temperatures. The sampling frequency should match those listed in Schedule 1 of Directive 49. Computer programs should be used to verify the flow calculations. All hand calculation procedures have been removed from this Directive.


B-2 Acid Gas Measurement

The quantity of acid gas going to sulphur plants is generally a low-pressure gas measurement at an average of 100 to 110 kPag; therefore, the orifice meter must be in excellent condition if accurate measurement is to be achieved. This measured volume is reported as Acid Gas on the gas plant monthly volumetric submission. Acid gas is saturated with water vapour, which represents a significant portion of the total gas measured. The amount of water vapour varies significantly with temperature. Therefore, it is necessary that there be a temperature record on a continuous basis. The gas gravity factor must also include the water content, and the orifice coefficient must include a factor to exclude the water vapour content of the gas in the final volume computation for reporting purposes. The accuracy of the gas gravity factor and water content determination must be checked. These calculations may have to be done by the operation personnel on a daily basis. If a meter or recording device other than an orifice meter is being used, it should be evaluated by the auditor in association with the ERCB Production Operation Section, Compliance and Operations Branch.

See Directive 017, section 11.2 for requirements (April 18, 2011)

Determining Acid Gas on a Dry Basis For ideal gases, the total vapour pressure of a system containing several components is the sum of the vapour pressure of the individual components at the temperature of the system. The components vapour pressure percentage of the total pressure of a system is equal to the volume percentage of that component in the system. 1) Determine the acid gas gravity on a wet basis. 2) Determine the acid gas and water vapour flow rate corrected from actual flowing

pressure and temperature to 101.325 kPaa and 15C. 3) The volume calculated in Step 2 contains water vapour and the pressure and

temperature related to this volume are 101.325 kPaa and 15C. Therefore, the factor used to correct the acid gas from a wet to dry basis is Correction Factor (CF)

= (101.325 kPaa vapour pressure of water at flowing temperature) / 101.325 kPaa Sample Acid Gas Calculation from Wet to Dry Basis

A. Gas Data

Hours produced = 24 h Flowing temperature = 33C


Flowing pressure = 17.9 kPag Atmospheric pressure = 99.3 kPaa


B. Component on a dry basis from acid gas analysis: (i) H2S = 90.1% CO2 = 9.1% C1 = 0.8%

C. Calculate percentage of components, including water vapour, on a wet basis:

Maximum percentage of water vapour = (100 x Vapour pressure of water at 33oC) / (Flowing pressure + Atmospheric pressure) Vapour pressure of water at 33oC = 5.075 (from the Saturated Steam table in the Thermodynamics section of the GPSA SI Engineering Data Book) Percentage of water vapour = (100 x 5.075) / (17.9 +99.3) = 4.33% Calculate new component percentages on a wet basis = 100% - 4.33% = 95.67% H2S = 90.1% x 95.67 / 100 = 86.199% CO2 = 9.1% x 95.67 / 100 = 8.706% C1 = 0.8% x 95.67 / 100 = 0.765% Revised analysis (wet basis): (ii)

Download - Directive 046

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